BC Q&A ecl 3 (00085646).DOC



PG&E’s 2009 RPS RFO

Bidder’s Conference & Imperial Valley Conference

July 21, 2009

Q&A Session

1. SDG&E’s RFP conference is on August 5th. Can you schedule the Bidder’s Workshop on another date that week (i.e., not on August 5th)?

Yes, PG&E has scheduled the bidder’s workshop for August 3, 2009 at 10 a.m. so as not to create a conflict with San Diego’s conference.

2. Is it required to bid a project in its entirety, or can it be bid in phases, e.g. 20 MW now plus 80 MW in phase 2?

Yes, you can bid in phases. Your offer should be clear regarding the start date and size of each phase, and it must specify whether there is a link between the phases. Let us know if the phases can be selected separately (e.g. first phase only or the second phase only), or whether the offer is for all phases only.

3. Can we propose contract lengths of greater than 20 years? Will a 25 or 30 year proposal be rejected?

Yes, you can bid a contract for longer than 20 years. Indicate the number of months in the box for “other” length in Attachment D and in the form PPA.

4. How will turnkey ownership and joint development offers be compared to PPA offers?

Please review the term sheet and joint development/ownership sheet included as attachments “I” and “M”, respectively, to the Solicitation Protocol. PG&E will estimate the lifetime cost of each project, including O&M, and convert the costs to a revenue requirement stream. The revenue requirement stream allows ownership offers to be directly compared to PPA offers for market valuation.

5. Is capacity value based upon noon to 6 PM super peak?

Capacity value is based on the California Public Utilities Commission’s (CPUC) Resource Adequacy (RA) counting rules. These rules have recently changed and capacity value depends on the resource type (Decision 09-06-028).



6. Any guidance on “ball park” capacity value of solar delivered noon to 6 PM?

These are PG&E’s proprietary values. Prior to the Offer deadline, PG&E will finalize and fix market price information. This information will be used to evaluate Offers from the Solicitation. PG&E will share the results of its application of market information to the Offers with the Independent Evaluator (IE) and our Procurement Review Group (PRG).

7. Can you discuss how viability and price will be weighted during response evaluation? For example, how will a project with high price and high viability compare to a project with lower price and lower viability?

All projects will be ranked by market valuation. Qualitative factors, including project viability will be considered as well. PG&E will use judgment to balance the values of price and viability.

8. How will projects in Southern California (outside of PG&E’s service area) be weighed as opposed to projects in Northern California? How are these measurements taken into account in the Locational Marginal Price (LMP)?

For projects in the CAISO control area, both within and outside PG&E’s service territory, PG&E will use the same quantitative and qualitative evaluation process described in the RPS Protocol. The quantitative assessment includes the application of a location specific LMP multiplier to estimate energy value.

9. If a project has a defined distribution interconnection cost, is there still a transmission adder?

If we know the distribution interconnection cost because the Interconnection study is done, we will use that information rather than apply an adder based on a transmission cost proxy. Be sure to include a copy of the study, which includes the cost estimate, with your Offer submission.

10. CAISO Interconnect. Can I submit 2 proposals next to each other so as to allow me to then process two separate 20 MW applications with CAISO?

If these are two separate projects and not two proposals for the same project (i.e. two separate 20 MW projects), then these two projects can be submitted individually into PG&E’s RPS solicitation. They can then utilize the Small Generator Interconnection Process (SGIP) instead of Large Generator Interconnection Process (LGIP).

If you have one 40 MW project and want to submit two 20 MW phases then this can be accommodated and they will be considered two separate projects.

11. What is the cost of a transmission study for 20MW or less?

The study costs can be several tens of thousand of dollars. Project costs will be looked at on a case by case basis. If utilities are performing a study for the CAISO, utilities will be compensated for their costs.

12. Does interconnection to PG&E distribution network require proceeding through SGIP at CAISO? If not, what is anticipated time line for interconnection?

Whether a project connects to the utility distribution system or to the FERC-regulated transmission system depends on the utility. For example, for PG&E, for the purpose of interconnection and operation, 60kV or greater is considered transmission, and if lower than 60kV, it is considered distribution. This level can be different for other utilities. SCE considers its distribution system as 115 kV and under. The CAISO is the gatekeeper to the interconnection process for all generation (i.e. >1MW) connected at the transmission service level. The CAISO will study any Federal Energy Regulatory Commission (FERC) jurisdictional generator greater than 2 MW connected at transmission, regardless of the SGIP or LGIP process.

13. Given that the interconnection process can take 2 or more years before full interconnect/gen-tie costs will be known, what interconnection and/or gen-tie associated costs can be passed onto PG&E?

None. The generator is responsible for all interconnection/gen-tie costs. The renewable energy sale price included in each Offer should reflect these costs.

14. Do contracts for site offers, joint development/ownership, turnkey ownership and PPAs with buyout options reduce or affect the utility-owned generation MWs?

No. There is no separate allocation or pre-determined quantity of utility-owned generation. PG&E will choose projects with the best overall economic and qualitative attributes (such as project viability).

15. How do 1.5 MW and larger PV systems located on leased industrial roof space fit into this RPS solicitation both in terms of a PPA and turn key ownership offer structure?

You may bid systems such as those into this Solicitation.

16. If I bid into the solicitation, am I not allowed to bid to the 250MW PV PPA?

Correct. If you bid the project into PG&E’s 2009 RPS Solicitation, are shortlisted, and agree to accept the position on the shortlist, then you will not be allowed to bid the same project into the PV program. Your agreement to be shortlisted constitutes an agreement to offer your project exclusively into this Solicitation with the goal of entering into a PPA with PG&E as part of this Solicitation. See the Solicitation Protocol for further information about bidder’s obligations upon shortlisting.

17. What is the definition of baseload (e.g. includes solar thermal with storage)?

Please see the definition in Protocol Appendix H, PPA, Article 1, 1.12. Be aware that the definition may need modification for solar thermal projects with storage.

18. Can you specify how the item “other proxy transmission upgrades” is attributed in case several projects require the upgrades? Prorated? First project takes all?

If more than one project fall within the same generation Level in the same cluster, the associated cost in “other proxy transmission upgrades” column shown in Table X.1 of the 2009 RPS Protocol will be allocated on a pro rata basis in bid evaluation. Please see CPUC Decision 05-07-040, Ordering Paragraph 3, which states, “In ranking RPS bids, PG&E, SCE, and SDG&E shall each allocate costs of transmission upgrades that would be used by more than one RPS project on a pro rata basis, based on the percentage of transfer capacity added by the proposed upgrade that would be used by the RPS project: This pro rata allocation of upgrade costs shall be applied only if sufficient renewables potential exists, as identified by the California Energy Commission, to fully utilize the transmission facility sometime in the future.”

19. Please walk thru use of Table X.1 in more detail. Which column would be used?

The table X.1 is the Transmission Ranking Cost table for the PG&E study clusters showing potential availability of transmission capacity and the associated Transmission Ranking Costs for various levels of potential RPS RFO bid. This Table is meant to provide information and some guidance to the bidders before the bid submittal to the bidders to aid in structuring their bid proposals. For those bidders that have not completed the CAISO Interconnection Process, PG&E will use the Transmission Ranking Costs in Table X.1 and other information submitted by the bidders (such as generation profile) to calculate the Transmission Adders for bid evaluation purposes. For bid evaluation, PG&E will use the both the Column with heading “Proxy Voltage Support Devices” and the Column with heading “Other Proxy Transmission upgrades” with the time periods that best reflect the Generation Profile and technology submitted by the bidder.

For more information on the Transmission Ranking Cost Report (TRCR), please see the PG&E web site.[1] For information on the use of the Transmission Ranking Costs in bid evaluation, please see CPUC Decision 04-06-013, Attachment A.

20. What happens if there are multiple projects at 1 cluster?

If there are multiple projects at one cluster, and if the proposed resources potential in the latest CEC or RETI reports exceeds the available transmission capacity, then upgrade costs are allocated based on use of added transmission capacity by proxy facility. Also see the answer to question 20.

21. Can IOU’s qualify for critical peak pricing (CPP) tariff option or is it only for demand side?

No, the PPA cannot qualify for critical peak pricing.

22. What happens if my actual interconnection costs are higher/lower than what was assumed for bid evaluation?

Interconnection costs are the responsibility of the counterparty. In the evaluation, PG&E uses network upgrade proxy costs for those generation projects that have not completed the CAISO Interconnection Process; however, regardless of whether the network upgrade costs end up higher or lower than the proxy estimate, it is the developer’s responsibility to fund these costs and the developer will get a refund over a five year period with interest after the project comes on line.

23. Can long term offers be priced on a flat rate with no TOD modifier (like the short term offers)?

No, each long-term offer should be bid with TOD factors. Otherwise, it will be considered non-conforming.

24. Example of 5MW solar power plant deposit?

Offer Deposit due with Protocol Agreement

$3/kW x 5 MW x 1000 kW/MW = $15,000

Project Development Security due upon execution of a 10-year PPA

$15/kW x 5 MW x 1000 kW/MW = $75,000

Project Development Security due within 30 days of CPUC Approval

$100/kW x 5 MW x 1000 kW/MW x 50% = $250,000

25. Please explain Slide 13: Timing of penalty payment and must “makeup” generation be > 90% as mentioned?

If you miss the Guaranteed Energy Production (GEP) requirement during the measurement period, then the next year, you have to meet the 90%. If you don’t meet the physical cure, then you can pay a financial cure of not less than $20/MWh for each MWh by which the project fails to achieve GEP for the relevant measurement period.

26. Please explain Slide 17: Is credit cumulative or ramped up?

It is ramped up or increased to the amount listed in the PPA for the given time period specified. Upon CPUC approval, your project development security will be a total of $100/kw*min(capacity factor, 50%).

27. Please explain Slide 46: Is 2 years for LGIP studies from the close of window?

Two years is the cumulative study time window for the Phase I and Phase II studies, when they are begun by the CAISO. The CAISO has an additional application period for a particular cluster and the CAISO may collect applications several months in advance of when the CAISO studies begin. 

28. If I missed the 80% annual, but exceed during other periods, can I still get penalized?

Yes. The GEP requirement is an annual requirement. Generation in specific time periods during the year is not a factor.

29. Can you confirm whether you require a firm transmission path from the busbar to a CAISO intertie for out of state projects?

We do not require a firm transmission path, but the energy does need to be delivered to the CAISO, so we will need a firming and shaping agreement in place so energy can get delivered to the CAISO.

30. Are you interested in bid options for out-of-state projects beyond a straight PPA, meaning site for sale, joint development, etc. or must they be located in California?

We are interested in out of state offers so long as the generating facility will be connected to the WECC transmission system.

31. If proposing a solar thermal project with gas firming, will gas-fired MWh’s be multiplied by the TOD factors:

PG&E is seeking renewable generation. Gas-fired MWh’s will not be paid a renewable price and will not be multiplied by TOD factors, in accordance with the CEC RPS Eligibility Guidebook,



32. Does this RPS solicitation include gas fired peakers as a renewable?

No. PG&E will only purchase renewable energy from projects certified as Eligible Renewable Energy Resources by the California Energy Commission.

33. If submitting offers with multiple locations, can we submit one offer for all locations, or do we have to submit one offer for each site?

We prefer one offer for each site since each site is evaluated separately.

34. What is the current average contract price ($/MWh) for non-dispatchable power?

Contract prices are confidential information.

35. Are we allowed to submit different projects entirely (as in different sites) or only 6 different variations of the same project?

You can submit as many projects as you want. These projects will be considered separate offers and a separate decision will be made on each offer.

36. Assuming there is a GEP deficit, will you consider power from another source?

No, we will not consider power from another source. In fact, Article 5.1 of the form of PPA included in the Solicitation Protocol states that delivery from a source other than the project is an event of default under the PPA.

37. Can we submit one project with multiple ownership structures?

Yes.

38. Can we have specifics about attachment M? Must we fill out all the information and will everything be looked at?

The joint ownership/development sheet (Attachment M), and all other applicable attachments, should be filled out in its entirety. We will look at everything you provide.

Projects with more complete information and in general that reduce the risk incurred by PG&E will receive more favorable scores. Participants should consider this in providing the information requested in Attachment M.

39. Is there a calculation framework for a buyout? Will the model framework be shared?

The buyout is evaluated as a swap option. Further detail on the framework is described in attachment K. PG&E’s model is proprietary.

40. Why would we submit an Imperial Valley project to PG&E?

There may be beneficial business reasons for the project to be bid into PG&E’s RFO. You may submit a bid into all three solicitations but you may negotiate the terms of that bid with only one utility.

41. Are the costs for the Sunrise project in the TRCR? (AMENDED)

The cost of the Sunrise Powerlink is a sunk cost in SDG&E’s 2009 TRCR.

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